Downhole gas separator apparatus

ABSTRACT

A downhole gas separator apparatus for separating gas from liquids during extraction of oil from the ground is disclosed. The apparatus can be used for high angle or horizontal wells, as well as low angle or vertical wells. The dimensions can vary to be used for extra heavy oil as well as light crude oil.

FIELD OF THE INVENTION

The invention relates to a new or improved downhole gas separatorapparatus for separating gas from liquids in well fluid duringextraction of oil, and in particular relates to a new or improveddownhole gas separator apparatus and method of separating gas and liquidin well fluid. The apparatus can be used for high angle or horizontalwells, as well as low angle or vertical wells. The dimensions can varyto be used for extra heavy oil as well as light crude oil.

BACKGROUND OF THE INVENTION

Throughout their productive life, most oil wells produce oil, gas, andwater. This mixture is separated at the surface. Initially, the mixturecoming from the reservoir may be mostly oil and gas with a small amountof water. Over time, the percentage of water increases. Increased waterproduction eventually leads to the need for artificial lift, since wateris heavier than oil. The pressure formed by the column of oil/watermixture in the wellbore may exceed the reservoir pressure. When thisoccurs, the well can no longer free flow by natural flow and artificiallift is required for the remainder of the well's life. In many oilwells, and particularly those in fields that are established and aging,natural pressure has declined to the point where the oil must beartificially lifted to the surface.

The most common type of artificial lift pump system applied is beampumping, which engages equipment on and below the surface to increasepressure in the well by and push oil to the surface. Consisting of asucker rod string and a sucker rod pump, beam pumps are the familiarjack pumps seen on onshore oil wells.

In beam pumping, subsurface pumps are located in the well below thelevel of the oil. A string of sucker rods extends from the pump up tothe surface to a pump jack device, beam pump unit or other devices. Aprime mover, such as a gasoline or diesel engine, an electric motor or agas engine, on the surface causes the pump jack to rock back and forth,thereby moving the string of sucker rods up and down inside of the welltubing.

The string of sucker rods operates a subsurface positive displacementpump called a sucker rod pump (“SRP”) having a plunger that isreciprocated inside of a barrel by the sucker rods. Reciprocationcharges a chamber between the valves with fluid and then lifts the wellfluid up the tubing towards the surface. The SRP is inserted or set inthe tubing near the bottom of the well. Each upstroke of the beam unitlifts the oil above the pump's plunger.

FIG. 1 depicts a beam pumping system for a producing oil well known inthe prior art. Production casing 10 extends from the surface equipment11 down to the producing zone 12. Production tubing 14 extendsdownwardly from the surface equipment at 11 to the area of the producingzone 12. The production tubing 14 comprises a series of joints screwedtogether to form a hollow, cylindrical production passageway 15 upwardlyto surface collection equipment illustrated by the collection line at16. The production tubing 14 is of a smaller external diameter than thecasing 10 such that an annular area or “annulus” 17 is formed betweenthe production casing 10 and production tubing 14. An annulus collectionline 18 collects gas from the annulus 17.

A pumping unit 19 is utilized which drives a rod or shaft 20 whichextends from the pumping unit downwardly through the production tubingto a pump 21. The shaft or rod 20 is called a “sucker rod” and the pump21 is called a “sucker rod pump.”

Typically, the SRP includes an outer housing 21 a that mounts pumpingpiston 21 b which is operably connected to the sucker rod 20 formovement between an up position at the end of the up stroke and a downposition at the end of the down stroke. Typically, such SRPs collectwell fluid within the housing 21 a during the down stroke of the piston21 b and pump well fluid outwardly of the pump housing 21 a and into theproduction tubing passageway 15 during the upstroke so that the wellfluid is collected from the surface line 16.

Another type of artificial lift pumping system is hydraulic pumpingequipment which utilizes a downhole hydraulic pump, rather than suckerrods, to lift well fluid to the surface. Well fluid is forced againstthe pistons, causing pressure and the pistons to lift the well fluids tothe surface. Similar to the physics applied in waterwheels poweringold-fashion gristmills, the natural energy within the well is put towork to raise the well fluid to the surface.

Progressing cavity pumps (PCP) are volumetric type (positivedisplacement) pumps that can be used in artificial lift pumping systems.PCP systems typically consist of a surface drive, drive string anddownhole PCP. The PCP comprises a single helical-shaped rotor that turnsinside a double helical stator. The stator is attached to the productiontubing and remains stationary during pumping. In most cases the rotor isattached to a sucker rod string which is suspended and rotated by asurface power unit. As the rotor turns eccentrically in the stator, aseries of sealed cavities form and progress from the inlet to thedischarge end of the pump. The result is a non-pulsating positivedisplacement flow with a discharge rate proportional to the size of thecavity, rotational speed of the rotor and the differential pressureacross the pump. The stator of a PCP has an elastomer covering that canbe damaged by gases such as carbon dioxide and hydrogen sulfide whichare typically encountered in oil wells.

FIG. 2 depicts a PCP system for a producing oil well known in the priorart. Electric submersible pump systems (ESP) are also used in artificiallift pumping systems. ESPs employ a centrifugal pump below the level ofthe well fluid. Connected to a long electric motor, the ESP comprisesseveral impellers, or blades, that spin and move the well fluid withinthe well. The system is installed at the bottom of the tubing string. Anelectric cable runs the length of the well, connecting the ESP to asurface source of electricity. The downhole components are suspendedfrom the production tubing above the wells' perforations. In most casesthe motor is located on the bottom of the work string. Above the motoris the seal section, the intake or gas separator, and the pump. Thepower cable is banded to the tubing and plugs into the top of the motor.As the well fluid comes into the well it must pass by the motor and intothe pump. This well fluid flow past the motor aids in the cooling of themotor. The well fluid then enters the intake and is taken into the pump.Each stage (impeller/diffuser combination) adds pressure or head to thefluid at a given rate. The well fluid will build up enough pressure asit reaches the top of the pump to lift it to the surface and into theseparator or flowline.

FIG. 3 depicts an ESP system for a producing oil well known in the priorart. In low pressure wells where gas is being produced along with oil,the gas tends to come out of the well fluid due to the low pressure ofthe well and may cause gas lock in the pump. Gas lock can reduce theefficiency of the pump substantially and can damage the pump. In verygaseous wells, the problem of gas lock in the pump can be of suchseverity that the well has to be shut. Typically, the more gas which canbe eliminated from the well fluid, the better the operation of the pump.

The presence of gas in the well fluid being pumped can also damage thepump through heat generation, cavitation and/or gas absorption. Forexample, PCPs rely for their lubrication and cooling on the liquid thatis being pumped. If this liquid contains too high a content of gas, thenthe pump will not be properly lubricated and cooled. Where lubricationand/or cooling are insufficient, then the pump stator may experienceaccelerated wear, and furthermore the heat generated by friction betweenthe rotor and the stator can cause the stator to be “cooked” or “burned”resulting in premature failure of the stator and the pump.

For pumping wells based on PCP, SRP and ESP, tubing anchor, torqueanchor or centralizers are typically used below the pump forstabilization purposes. These stabilizers force pump intake to becentralized and act adversely in term of gas liquid separationefficiency by allowing more gas to be dragged to the pump intake,reducing pumping efficiency and reducing run life in many cases.

As noted, low pumping efficiency can greatly increase operating expensesof the well due to, among others, excessive electrical power usage, adecrease in the amount of production from the well and additionalmaintenance requirements due to inefficient loadings of the pumpingunit, rod string, motor and pump. To increase pumping efficiency it iscommon for downhole gas separators (DGSs) that separate gas from theliquid mixture in well fluid to be installed in the production tubingbelow the intake of the pump. The main purpose of the DGS is to enhancethe generation of gas bubbles that can then be released through theproduction casing annulus.

Various types of DGSs are currently available. Conventional separatorstypically use bubbling separation but generally have a lower separatingefficiency than is desirable. Cascade flow type separators, stratifiedtype separators and Jukovski effect type separators generally offergreater efficiency over conventional separators. However, theseseparators depend on the level of liquid within them being maintainedwithin a specified range which requires the use of an external manual orautomatic control system based on sensors, valves and links betweenthem. Such control systems and sensors are vulnerable points that addcomplexity to the system.

For example, in FIG. 1, an oil/gas separator S (DGS) is shown to bemounted at the end of the production tubing or string 14 in an areaadjacent to the producing zone 12 in order to receive the oil/gasmixture flowing from the production zone 12 and separate sufficient gasout of the oil/gas mixture to avoid gas lock in the sucker rod pump 21.

SUMMARY OF THE INVENTION

The downhole gas separator apparatus for heavy oil according to theinvention is a production optimization tool for improve pumpingefficiency for SRP, PCP and ESP systems, allowing liquid-rich well fluidto be delivered to pump intake. The downhole gas separator apparatusthus helps to improve run life of the pump and oil production byincreasing oil production and volumetric efficiency. By reducing freegas at the pump intake, operating conditions are improved allowingconsiderable savings in power, downhole pump sizes (smaller pumps toachieve same liquid rate) and rig services due to extended run life thatcan be achieved by improvement of pumping conditions.

The downhole gas separator apparatus comprises an internal element andan external element, and is disposed within the production casing belowthe pump intake. Two eccentric annuli are formed: (1) one annulus isformed between the external element and the production casing, where theexternal element is placed in an offset position related to theproduction casing (the “first eccentric annulus”) and (2) one annulus isformed between the internal element and the external element, where theinternal element is placed in an offset position related to the externalelement (the “second eccentric annulus”). The downhole gas separatorapparatus further comprises a sealing element at the bottom end of theexternal element that prevents well fluid from entering the apparatusfrom the production casing. The downhole gas separator apparatus furthercomprises a plurality of intake ports disposed at the top end leadinginto the second eccentric annulus. The internal element and the outerelement are further disposed such that well fluid flows from the secondeccentric annulus into the internal element at the bottom of theapparatus.

The downhole gas separator apparatus is installed below the pump intake(and pump centralizer). The first eccentric annulus and the secondeccentric annulus together enhance gas-liquid separation based ondensity differences of oil and gas as well as changes of flow directionof well fluid. The dual eccentric annulus design creates preferentialpaths for liquid and gas flow.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described with reference to the accompanyingdrawings, in which like elements are referenced with like numerals.

FIGS. 1 to 3 depict artificial lift pump systems known in the prior art.

FIGS. 4A-B depict Average Pump Intake (PIP) and Pump Discharge Pressure(PDP) before (where available) and after running with the downholegas-oil separator apparatus of the invention installed.

FIGS. 5A-D provide a comparison of liquid rate before (stableconditions) and after installation of the apparatus of the invention(optimized point) was carried out.

FIGS. 6A-B provide data regarding separation efficiency with and withoutthe downhole gas-oil separator apparatus of the invention.

FIGS. 7A-7G depict views of the external element and the interiorelement comprising the downhole gas separator apparatus according to oneembodiment of the invention.

FIG. 8 depicts an end view of the downhole gas separator apparatusaccording to one embodiment of the invention.

DETAILED DESCRIPTION OF THE INVENTION

The downhole gas separator apparatus for heavy oil according to theinvention is a production optimization tool for improve pumpingefficiency for SRP, PCP and ESP systems, allowing liquid-rich well fluidto be delivered to pump intake. The downhole gas separator apparatusthus helps to improve run life of the pump and oil production byincreasing oil production and volumetric efficiency. By reducing freegas at the pump intake, operating conditions are improved allowingconsiderable savings in power, downhole pump sizes (smaller pumps toachieve same liquid rate) and rig services due to extended run life thatcan be achieved by improvement of pumping conditions.

The downhole gas separator apparatus comprises an internal element andan external element, and is disposed within the production casing belowthe pump intake. Two eccentric annuli are formed: (1) one annulus isformed between the external element and the production casing, where theexternal element is placed in an offset position related to theproduction casing (the “first eccentric annulus”) and (2) one annulus isformed between the internal element and the external element, where theinternal element is placed in an offset position related to the externalelement (the “second eccentric annulus”). A sealing element at thebottom end of the external element prevents well fluid from entering thedownhole gas separator apparatus from the production casing. Thedownhole gas separator apparatus comprises a plurality of intake portsdisposed at the top end leading into the second eccentric annulus. Theinternal element and the outer element are disposed such that well fluidflows from the second eccentric annulus into the internal element at thebottom of the apparatus.

The downhole gas separator apparatus is installed below the pump intake(and pump centralizer). The first eccentric annulus and the secondeccentric annulus together enhance gas-liquid separation based ondensity differences of oil and gas as well as changes of flow directionof well fluid. The dual eccentric annulus design creates preferentialpaths for liquid and gas flow.

Well fluid is forced to flow upward through first eccentric annulusbetween the production casing and the external element. The flow of wellfluid through the first eccentric annulus promotes separation of oil andgas and helps in segregating gas-rich multiphase flow to the top of theproduction casing. As the well fluid flows upward it reaches the intakeports at the top of the external element of the downhole gas separatorapparatus, whereupon it changes its direction orthogonal to the previousflow direction to flow downward through the second eccentric annulus.Gas is separated from oil as the liquid-rich multiphase well fluid as itflows downward, which gas is released and flows upward through theproduction casing to the surface. The liquid-rich multiphase well fluidtravels downward through the second eccentric annulus until it reachesthe bottom of the downhole gas separator apparatus, whereupon itswitches flow direction again and moves upward into and the internalelement through the internal element intake ports. This liquid-richmultiphase flow is directed to the pump intake.

The downhole gas separator apparatus can be manufactured using standardOCTG tubular, making it compatible with standard tubing tongues andtools. Accordingly, no special tools such as xover, elevators or fishingtools are required for installation or removal. Due to its dualeccentric annulus design, the apparatus provides higher area at the topof the annulus, and the external and internal annuli open to flow arewell balanced to achieve optimal flowing well fluid velocities toimprove gas-oil separation based on natural segregation and gas rise andcoalescence. Intake (and gas outlet ports) are dimensioned toaccommodate fluid shear and low pressure drop at high rates or highviscosity, making the apparatus suitable for extra-heavy oilapplications. Elements can be disposed in the second eccentric annulusto create turbulence and wavy fluid behavior to increase contact betweendescending mixture and ascending gas bubbles. The seal element at thebottom of the apparatus helps prevent clogging of the inner element ofthe apparatus by solids in the well fluid. In the event of clogging,reverse flow can be achieved to flush the inner element.

Conventional separators based on flow segregation are conceived forliquid rates not higher than 500 BPD in light to medium crude (lowviscosity) and 100 to 300 BPD in heavy crude application (withconsiderably higher pressure drop). The downhole gas separator apparatuscan accommodate gas rates higher than 5 million SCFD and higher than1000 BPD (field proven). The apparatus can be adapted to virtually anywell condition by scaling its size (length, OD, ID) according to wellconfiguration and fluid properties. Pre-existing equipment can bearranged in tandem arrays to further improve its operating range.Apparatus reconfiguration is based mainly in flow areas, velocityprofiles and flow properties to achieve the optimal scenario to allowgas bubbles to rise thru the well fluid and be released through the twoannuli. This apparatus further can accommodate the option to inject H2Sscavengers, diluent, viscosity reductors and other chemicals to theinner part of the apparatus through (if required) an optional capillarytube port. This apparatus does not require any particular operationpressure and unlike traditional poor boy, cups type or other separators,this apparatus can be used with well fluid comprising viscous crude oilwith high angles (>30°) providing low flow resistance, allowing apermanent liquid bed to be disposed on top of the intake ports whichprevents free gas from easily entering into the pump intake from theinner element. This apparatus can also be combined with annulus backpressure systems.

Since most of the gas is vented to the annulus before reaching thePCP/SRP/ESP intake, liquid-rich well fluid is delivered to the pumpwhich translates into benefits as:

-   -   Increased volumetric efficiency    -   Reduction of equipment sizing as volumetric efficiency increases    -   Less premature failures due to hysteresis or high gas volume at        pump intake    -   Prevents gas lock and/or intermittent flow thru tubing.    -   Able to deal with same liquid rate at considerably lower RPM.    -   Reduction of pumping RPM/SPM results in less friction, less        tubing wear and less system failures.    -   Pumping efficiency and power consumption (kw/barrel) increases        considerably.    -   PCP size can be reduced by 30-50% maintaining the same liquid        rate in high GOR conditions.    -   For the same PCP/SRP size more liquid can be produced at same or        lower RPM/SPM.    -   The design, does not require any special tools for installation        or removal.

The downhole oil-gas separator of the invention was originally designedfor use with Orinoco Oil Belt (OOB) heavy crude. However, the scalabledesign of the invention allows the apparatus to be reconfigured to matchwell conditions.

-   -   Designed for liquid rates between 40-1500 BPD and gas rates        0.1-5.5 Million SCF/D (Field Tested)    -   Gas Lock and/or flow intermittence is minimized or eliminated        (depending on well conditions)    -   Compatible with annular back pressure systems as        SIAP/MAXIPROD/AWPA/ETC.    -   Filtering (debris) and tubing integrity (leak detection) testing        capabilities can be added.

This apparatus has been installed and evaluated so far in more than 30wells.

The average field properties where the apparatus has been installed andevaluated are the following:

API 17 Average/14 (Min)/19 (Max) GOR 120-5500 SCF/STB Liquid Rate perwell 40-3000 STB/Day PCP Seating Depth 3600-3900 FT (MD) PCP Seating Dep3400-3600 FT (TVD) Artificial Lift Methods 100% PCP Tubing String 5-½LTC J55 or 4-½ EUE N80 Sucker Rod String 1¼″ or 1½″ (1 9/16″ pin size)Number of Active Wells 85 Wells Number of Active Pads 15 Pads AverageField Production 36

Pressures:

During field test wells with downhole sensor and downhole separator(DHS) were kept under constant observation. FIGS. 4A-B depict AveragePump Intake (PIP) and Pump Discharge Pressure (PDP) before (whereavailable) and after running with the downhole gas-oil separatorapparatus of the invention installed. Several wells were sent toworkover before PCP failure to run in PCP Separator. Two wells with lowPCP run time had the PCP's reinstalled to determine what the behavior isbefore and after running in the apparatus of the invention (having thesame pump). Real Time Monitoring reported thru tubing improved liquidgradient higher PDP) was observed in all the wells with DHS.

Field Test

Production Rate:

FIGS. 5A-D provide a comparison of liquid rate before (stableconditions) and after installation of the apparatus of the invention(optimized point) was carried out. Field test reports overall productionincreased in most wells evaluated so far since January 2013. Most of thewells increased liquid rates after installing and optimizing the system.

Some intermittent and low PI Wells (before installing) did not reflectadditional oil rate but a stable flow condition (gas free) was observedin all of them with no intermittent flow that previously was the “normalcondition” for such wells. Same liquid rate was achieved with less RPMor more liquid rates with same RPM (or lower). So far additional crudebeing produced due to gas separator installation represent aconsiderable amount of the 2013 production generation campaign for thisfield.

A special production test was run in two wells with very similarcompletion, flowing conditions and parameters. The test consisted inmeasuring total liquid rate and total gas rate first. Thereafter onlythru tubing gas rate and total liquid rate was sampled (annulus divertedto gas gathering line maintaining same Casing Head Pressure).

Natural separation (NO SEPARATOR INSTALLED) was reported to be 76%approximately considering thru tubing gas rate divided by total gas ratefor selected well with no separator. The well WITH SEPARATOR INSTALLEDreported 95% of gas separation under same conditions. Both tests forboth wells were taken the same day on the same PAD with the same welltester.

Natural and Artificial Separation Efficiency

A special production test was run in two wells with very similarcompletion, flowing conditions and parameters. The test consisted inmeasuring total liquid rate and total gas rate first. Thereafter onlythrough tubing gas rate and total liquid rate was sampled (annulusdiverted to gas gathering line maintaining same Casing Head Pressure).

As seen in FIGS. 6A-B, natural separation (NO SEPARATOR INSTALLED) wasreported to be 76% approximately considering thru tubing gas ratedivided by total gas rate for selected well with no separator. The wellWITH SEPARATOR INSTALLED reported 95% of gas separation under sameconditions. Both tests for both wells were taken the same day on thesame PAD with the same well tester.

FIGS. 7A-7G depict views of the downhole gas separator apparatusaccording to one embodiment of the invention. The downhole gas separatorapparatus comprises an external element 710 (FIG. 7A) and an internalelement 720 (FIG. 7B). External element 710 comprises a plurality ofsecond eccentric annulus intake ports 730 dispersed around thecircumference toward the top of external element 710. Top end 750 ofexternal element 710 is disposed proximal to the pump intake (not shown)and bottom end 760 distal from the pump intake. Internal element 720comprises a plurality of turbulence devices 740 that create turbulenceand wavy fluid behavior to increase contact between descending mixtureand ascending gas bubbles. The design of devices 740 can vary accordingto the decision of the designer. Top end 770 of internal element 720 isdisposed proximal to top end 750 of external element 710 and bottom end780 of internal element 720 is disposed proximal to bottom end 760 ofexternal element 710. Internal element 720 further comprises internalelement intake ports 790 disposed at bottom end 780.

FIG. 7C depicts internal element 720 inserted in interior cavity 715 ofexternal element 710 thus forming eccentric annulus 820 (the “secondeccentric annulus” as described further in FIGS. 8A-B). Top end 750 ofexternal element 710 is disposed proximal to the pump intake (not shown)and bottom end 760 distal from the pump intake. Top end 770 of internalelement 720 is disposed top end 750 of external element 710 and bottomend 780 of internal element 720 is disposed proximal bottom end 760 ofexternal element 710. Internal element 720 further comprises internalelement intake ports 790 disposed at bottom end 780. The downhole gasseparator apparatus further comprises a sealing element 765 at thebottom end 760 of the external element 710 that prevents well fluid fromentering the apparatus from the production casing (not shown).

As seen in FIG. 7C, internal element 720 and external element 710 aredisposed such that well fluid flows from the second eccentric annulusinto interior cavity 725 of internal element 720 at one end 715 of theexternal element 720.

FIG. 7D depicts a close up view of top end 750 of external element 710showing second eccentric annulus intake ports 730.

FIG. 7E depicts a close up view of the mid-section of internal element720 showing turbulence devices 740.

FIG. 7F depicts a cross-sectional view of the top end 750 of internalelement 720 inserted into cavity 715 of external element 710, showingsecond eccentric annulus intake ports 730; second eccentric annulus 820;and interior cavity 725 of internal element 720.

FIG. 7G depicts a cross-sectional view of the bottom end 760 of internalelement 720 inserted into cavity 715 of external element 710, showingsecond eccentric annulus intake ports 730; internal element intake ports790; second eccentric annulus 820; and interior cavity 725 of internalelement 720.

FIG. 8 depicts an end view of the downhole gas separator apparatus 700of FIGS. 7A-7G according to one embodiment of the invention showing thetwo eccentric annuli that are formed. The first eccentric annulus 810 isformed between the external element 710 and the production casing 830,where the external element 710 is placed in an offset position relatedto the production casing 720. The second eccentric annulus 820 is formedbetween the internal element 720 and the external element 710, where theinternal element 720 is placed in an offset position related to theexternal element 710.

In the foregoing description, the invention has been described withreference to specific exemplary embodiments thereof. It will be apparentto those skilled in the art that a person understanding this inventionmay conceive of changes or other embodiments or variations, whichutilize the principles of this invention without departing from thebroader spirit and scope of the invention. The specification anddrawings are, therefore, to be regarded in an illustrative rather than arestrictive sense.

What is claimed is:
 1. A downhole gas separator apparatus comprising: anexternal element comprising an external element outer wall, an externalelement inner wall, an external element top end, an external elementbottom end, an external element interior cavity, a seal that preventsthe flow of fluid into the external element interior cavity from theexternal element bottom end and a plurality of external element intakeports around the circumference of the external element substantiallytoward the top end of the external element; and an internal elementcomprising an internal element outer wall, an internal element innerwall, an internal element top end, an internal element bottom end, aninternal element interior cavity and a plurality of internal elementintake ports around the circumference of the internal elementsubstantially toward the bottom end of the internal element; wherein theexternal element is disposed within the interior of a production casingwith the external element top end below the intake of a pump that formspart of an artificial lift pumping system of a producing oil well,wherein the external element outer wall and the inner wall of theproduction casing form a first eccentric annulus; wherein the internalelement is disposed within the external element interior cavity, whereinthe internal cavity outer wall and the external cavity inner wall form asecond eccentric annulus, wherein the internal element top end isconnected to the pump intake.
 2. The downhole gas separator apparatus ofclaim 1, wherein the first eccentric annulus is placed in an offsetposition related to the production casing.
 3. The downhole gas separatorapparatus of claim 2, wherein the internal element is placed in anoffset position in relation to the external element to form the secondeccentric annulus.
 4. The downhole gas separator apparatus of claim 1,wherein the internal element exterior wall comprises a plurality ofelements that create turbulence in a fluid that flows through the secondeccentric annulus.
 5. The downhole gas separator apparatus of claim 1,wherein the pump comprises a sucker rod pump, a progressing cavity pumpor an electric submersible pump.
 6. The downhole gas separator apparatusof claim 1, wherein the producing oil well comprises a high angle well,a horizontal well, a low angle well or a vertical well. The dimensionscan vary to be used for extra heavy oil as well as light crude oil
 7. Amethod of separating gas and liquid flowing upward through theproduction casing of a producing oil well, comprising: disposing adownhole gas separator apparatus into the interior of the productioncasing of a producing oil well below the intake of a pump that formspart of an artificial lift pumping system of the producing oil well,wherein the downhole gas separator apparatus comprises: an externalelement comprising an external element outer wall, an external elementinner wall, an external element top end, an external element bottom end,an external element interior cavity, a seal that prevents the flow offluid into the external element interior cavity from the externalelement bottom end and a plurality of external element intake portsaround the circumference of the external element substantially towardthe top end of the external element; and an internal element comprisingan internal element outer wall, an internal element inner wall, aninternal element top end, an internal element bottom end, an internalelement interior cavity and a plurality of internal element intake portsaround the circumference of the internal element substantially towardthe bottom end of the internal element; wherein the external elementouter wall and the inner wall of the production casing form a firsteccentric annulus; wherein the internal element is disposed within theexternal element interior cavity, wherein the internal cavity outer walland the external cavity inner wall form a second eccentric annulus,wherein the internal element top end is connected to the pump intake;flowing a multiphase fluid comprising gas and oil upward through thefirst eccentric annulus between the inner wall of the production casingand the external element outer wall, during which time gas separatesfrom the multiphase fluid; diverting the flowing multiphase fluid intothe second eccentric annulus through the external element intake ports;diverting the flowing multiphase fluid into the internal elementinterior cavity through the internal element intake ports; and feedingthe flowing multiphase fluid into the pump intake at the internalelement top end; wherein gas that separates from the multiphase fluidflows upward through the production casing and is released; wherein themultiphase fluid that reaches the pump intake comprises less gas thanthe multiphase fluid that entered the first eccentric annulus.
 8. Themethod of claim 7, wherein the first eccentric annulus is placed in anoffset position related to the production casing.
 9. The method of claim8, wherein the internal element is placed in an offset position inrelation to the external element to form the second eccentric annulus.10. The method of claim 7, wherein the internal element exterior wallcomprises a plurality of elements that create turbulence in a fluid thatflows through the second eccentric annulus.
 11. The method of claim 7,wherein the pump comprises a sucker rod pump, a progressing cavity pumpor an electric submersible pump.
 12. The method of claim 7, wherein theproducing oil well comprises a high angle well, a horizontal well, a lowangle well or a vertical well.
 13. The method of claim 7, wherein themultiphase fluid comprises extra heavy oil.
 14. The method of claim 7,wherein the multiphase fluid comprises light crude oil.